Apparatus and method of processing multi-component induction data

ABSTRACT

A method includes acquiring signals generated from operating a multi-component induction tool in a wellbore. The multi-component induction tool has a plurality of receiver arrays. The method includes generating, for each receiver array at a fixed frequency, a combination of components from the acquired signals, wherein the components corresponds to components of an apparent conductivity tensor. The generating of the combination of components includes generating vertical magnetic dipole (VMD) data and horizontal magnetic dipole (HMD) data. The method includes mixing together the combination of VMD data and HMD data measured from the plurality of receiver arrays and generating data, with respect to evaluation of a formation around the wellbore, from the mixing together of combinations.

TECHNICAL FIELD

The present invention relates generally to apparatus and methods formaking measurements related to oil and gas exploration.

BACKGROUND

In drilling wells for oil and gas exploration, understanding thestructure and properties of the associated geological formation providesinformation to aid such exploration. Measurements in a wellbore, asreferred to as a borehole, are typically performed to attain thisunderstanding. However, the environment in which the drilling toolsoperate is at significant distances below the surface and measurementsto manage operation of such equipment are made at these locations.

Logging is the process of making measurements via sensors locateddownhole, which can provide valuable information regarding the formationcharacteristics. For example, induction logging can utilizeelectromagnetic signals that can be used to make measurements. Further,the usefulness of such measurements may be related to the precision orquality of the information derived from such measurements.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a schematic representation of components of amulti-component induction (MCI) tool, in accordance with variousembodiments.

FIG. 2 shows a schematic representation of an example MCI tool, inaccordance with various embodiments.

FIG. 3 shows a plot of a vertical geometrical factor (VGF) for eacharray of a four-array MCI tool at zero background conductivity, inaccordance with various embodiments.

FIG. 4 shows a radial geometrical factor (RGF) for each array of afour-array MCI tool at zero background conductivity, in accordance withvarious embodiments.

FIG. 5 shows features of an example method of processing MCI data, inaccordance with various embodiments.

FIG. 6 depicts a block diagram of features of an example system arrangedto process signals from a MCI tool structure operable in a wellbore, inaccordance with various embodiments.

FIG. 7 depicts an embodiment of a system at a drilling site, where thesystem includes a MCI tool structure and a processing unit operable toprocess MCI data, in accordance with various embodiments.

DETAILED DESCRIPTION

The following detailed description refers to the accompanying drawingsthat show, by way of illustration and not limitation, variousembodiments in which the invention may be practiced. These embodimentsare described in sufficient detail to enable those skilled in the art topractice these and other embodiments. Other embodiments may be utilized,and structural, logical, and electrical changes may be made to theseembodiments. The various embodiments are not necessarily mutuallyexclusive, as some embodiments can be combined with one or more otherembodiments to form new embodiments. The following detailed descriptionis, therefore, not to be taken in a limiting sense.

In various embodiments, apparatus and methods include techniques toprocess MCI data. The measurements of a multi-component array inductiontool can be processed to produce curves with improved resolution atmultiple depths of investigation and to provide resolution matchedcurves that are sensitive to specific formation features at variabledepths of investigation. These curves can provide additional informationfor the formation evaluation and/or be used as quality indicators.

MCI tool measurements can be combined to produce resolution matchedcurves at different depths of investigation for different combinedcomponents of an apparent conductivity tensor. The processing of thesedifferent combinations of MCI measurements can be used to describe theformation in a more detailed manner to aid in the process of formationevaluation and produce useful processing quality indicators. There are anumber of specific examples described herein for some of thesecombinations, which demonstrate the usefulness of the techniques and animprovement produced by such techniques.

FIG. 1 shows a schematic representation of components of an example MCItool. The components include a triaxial transmitter triad and a triaxialreceiver triad with two parts: a main coil and a bucking coil. Thetriaxial main receivers are separated from the triaxial transmitters bya distance L_(m), which is greater than the distance L_(b) at which thetriaxial bucking receivers are separated from the triaxial transmitters.A triad sensor is a structure having three sensors at the same location,where the position or orientation of the three sensors is different fromeach other. The three sensors of the triad can be mounted on the samestructure at a given location. A triaxial triad includes each of thethree sensors arranged on an axis of a tool, orthogonal to each other.The configuration shown in FIG. 1 is an example of one of several designoptions for a MCI-type tool. The type of data that can be produced bysuch a MCI tool includes data generated by a multi-component arrayinduction tool that generates data at different depths of investigation.

FIG. 2 shows a schematic representation of an embodiment of an exampleMCI tool. The MCI tool includes a transmitter triad 212, four receivertriads 214-1, 214-2, 214-3, and 214-4, as well as two conventional axialreceivers 213-1 and 213-2. The conventional receivers are locatedclosest to the transmitter triad. The receivers are separated from thetransmitter triad. For example, one conventional axial receiver 213-1can be separated from the transmitter triad by 6 inches and the secondconventional axial receiver 213-2 can be separated from the transmittertriad 212 by 9 inches. The first receiver triad 214-1 can be separatedfrom the transmitter triad 212 by 17 inches, the second receiver triad214-2 can be separated from the transmitter triad 212 by 29 inches, thethird receiver triad 214-3 can be separated from the transmitter triad212 by 50 inches, and the fourth receiver triad 214-4 can be separatedfrom the transmitter triad 212 by 80 inches. A MCI tool can bestructured with other separation distances. The distances above arementioned, since calculations were performed at these separationdistances in some of the discussions that follow. The configurationshown in FIG. 2 is an example of one of several design options for aMCI-type tool. The type of data that can be produced by such a MCI toolincludes data generated by a multi-component array induction tool thatgenerates data at different depths of investigation.

The MCI tool can include an electronic housing 217. The electronichousing 217 can include a control unit to selectively activate thetransmitter triad 212 and to selectively acquire signals from thereceiver triads 214-1, 214-2, 214-3, and 214-4, and the conventionalaxial receivers 213-1 and 213-2 in response to a probe signaltransmitted from the transmitter triad 212. The electronic housing 217can include a processing unit to operate on the received signals. Theprocessing unit of the electronic housing 217 may also be arranged toprocess MCI data derived from the received signals in a manner similarto or identical to techniques taught herein.

Each receiver triad can measure an apparent conductivity tensor of theform shown in equation 1:

$\begin{matrix}{{{\overset{=}{\sigma}}_{a} = {\left( \sigma_{ij} \right)_{({3 \times 3})} = {\begin{pmatrix}\sigma_{xx} & \sigma_{xy} & \sigma_{xz} \\\sigma_{yx} & \sigma_{yy} & \sigma_{yz} \\\sigma_{zx} & \sigma_{zy} & \sigma_{zz}\end{pmatrix} = \begin{pmatrix}\frac{V_{xx}}{K_{xx}^{V}} & \frac{V_{xy}}{K_{xy}^{V}} & \frac{V_{xz}}{K_{xz}^{V}} \\\frac{V_{yx}}{K_{yx}^{V}} & \frac{V_{yy}}{K_{yy}^{V}} & \frac{V_{yz}}{K_{yz}^{V}} \\\frac{V_{zx}}{K_{zx}^{V}} & \frac{V_{zy}}{K_{zy}^{V}} & \frac{V_{zz}}{K_{zz}^{V}}\end{pmatrix}}}},} & (1)\end{matrix}$where V_(ij) are the measured voltages on the receiver antennas. Thesemeasured voltages can be calibrated (normalized to) to apparentconductivities in equation (1). Here, σ_(a) is the MCI apparentconductivity tensor in the tool coordinate system (x_(t), y_(t),z_(t))shown in FIG. 1,

$\sigma_{ij} = \frac{V_{ij}}{K_{ij}^{V}}$are the components of the apparent conductivity tensor, K_(ij) ^(V) isthe calibration factor (or tool constant) of the tensor coupling a. Ingeneral, one can let K_(xx) ^(V)=K_(yy) ^(V)=K_(xy) ^(V)=K_(yx) ^(V),and K_(xz) ^(V)=K_(yz) ^(V)=K_(xz) ^(V)=K_(zy) ^(V) if the MCI tool canbe approximated as a dipole-type tool. Therefore, there are only threeindependent calibration factors in this case for a given triaxialsubarray and a given operated frequency: K_(zz) ^(V), K_(xx) ^(V), andK_(xz) ^(V).

A combination of measurements can be made to improve vertical resolutionof results for the horizontal formation resistivity Rh. It has beenshown that resolution can be improved and borehole effect andshoulder-bed effect can be reduced by combining the vertical magneticdipole (VMD) and the horizontal magnetic dipole (HMD) couplings of astandard collocated MCI triad. In terms of the MCI measurements, the VMDcorresponds to the ZZ coupling and the HMD corresponds to the XX or YYcoupling.

In various embodiments, a method is provided to achieve high resolutionwith variable depth of investigation. This can be accomplished bycombining different component data from the different arrays of the MCItool. With the different receiver arrays of the MCI tool at differentdistances from a transmitter of the MCI tool, signals received at thereceiver arrays in response to a probe signal generated by thetransmitter investigate different depths of the surrounding formation.Investigation of different depths of the formation can also be attainedby operating at different frequencies. Such processing can deliverhigher resolution matching multiple depths of investigation than resultsfor the standard Rh measurements of an MCI tool.

Component combinations corresponding to an apparent conductivity tensorfrom the different arrays can be generated with the following form:σ_(dc) ^((i)) =a ^((i))·σ_(zz) ^((i)) +b ^((i))·σ_(xx) ^((i)) +c^((i))·σ_(yy) ^((i)),  (2)where σ_(dc) ^((i)) are called the direct-coupling combined-log signalsfor a multi-array MCI tool, the three coefficients a^((i)), b^((i)) andc^((i)) are the constants for fixed array i and fixed frequency, andgenerally 0≤a^((i))+b^((i))+c^((i))≤1. In some embodiments, all threecoefficients a^((i)), b^((i)), and c^((i)) are non-zero. A secondcombination form can be generated as:σ_(cc) ^((i)) =d ^((i))·σ_(IJ) ^((i)) +e ^((i))·σ_(IJ) ^((i)),  (3)where σ_(cc) ^((i)) are called the cross-coupling combined-log signals,the two coefficients d^((i)) and e^((i)) are also the constants forfixed array i and fixed frequency, and d^((i)) and e^((i)) can be set tosatisfy 0≤d^((i))+e^((i))≤1.0. For example, if I=x, J=z, andd^((i))=e^((i))=0.5, then the combined-log signal σ_(cc) ^((i)) is(XZ+ZX)/2 from the cross-couplings XZ and ZX of the conductivitycomponent for the fixed array i, which is more sensitive to anisotropythan some other combinations. In this nomenclature XZ correlates to theXZ component of the apparent conductivity tensor and ZX correlates tothe ZX component of the apparent conductivity tensor. Similarnomenclature is used for the other components of the apparentconductivity tensor. If I=x, J=z, and d^((i))=0.5, e^((i))=−0.5, thecombined-log signal σ_(cc) ^((i)) is (XZ−ZX)/2, which is more sensitiveto bed boundaries than some other combinations.

An example of combined measurements to achieve higher resolution,reduced borehole effect, and reduced shoulder-bed effect is1.5*ZZ−0.5*XX−0.5*YY, which is the direct-coupling combined-log signalsof equation (2) with a^((i))=1.5, b^((i))=−0.5, and c^((i))=−0.5. FIG. 3shows a vertical geometrical factor (VGF) for each array of a four-arrayMCI tool at zero background conductivity for the component combination1.5*ZZ−0.5*XX−0.5*YY. Curve 342 shows the VGF for the array having a 17inch separation. Curve 344 shows the VGF for the array having a 29 inchseparation. Curve 346 shows the VGF for the array having a 50 inchseparation. Curve 348 shows the VGF for the array having an 80 inchseparation. FIG. 3 also shows reduced shoulder-bed effect. The VGF ismeasure of response of the tool along the tool axis as a function ofdistance from the tool related to the geometry of the tool.

FIG. 4 shows a radial geometrical factor (RGF) for each array of thefour-array MCI tool at zero background conductivity for the componentcombination 1.5*ZZ−0.5*XX−0.5*YY. Curve 452 shows the RGF for the arrayhaving a 17 inch separation. Curve 454 shows the RGF for the arrayhaving a 29 inch separation. Curve 456 shows the RGF for the arrayhaving a 50 inch separation. Curve 458 shows the RGF for the arrayhaving an 80 inch separation. The RGF is measure of a radial response ofthe tool perpendicular to the tool axis as a function of distance fromthe tool related to the geometry of the tool.

These combinations of tensor component measurements can be developedinto resolution match of multiple depths of investigation by mixingtogether the combinations measured from the different arrays of the MCItool. The results of this processing can be used as quality indicatorsor provide additional information in the formation evaluation process.

The signal processing method for the traditional array induction datathat combines measurements from different receiver arrays located atdifferent distances from the transmitter relies on concepts fromgeometrical factor theory, which is a good approximation in the highresistivity limit. Such a framework can be used to derive a processingmethod for the combinations of signals in equations (2) and (3). Thisapproach leads to the development of filters that can be applied to thecombined tensor components of equations (2) and (3) from the differentarrays of the MCI tool. These filters can be derived by using standardapproximations such as Doll's geometrical theory or Born approximationmethod. The following discussion provides features of an embodiment ofan example development of filters. For this example, the standardapparent conductivity is used in the presentation, but is replaceable inall expressions by the combinations shown in equations (2) and (3).

From the electromagnetic Born approximation theory, the combinedapparent conductivity σ_(a) ^((i))(z) of the MCI tool may be expressedas a the double integral in a cylindrical coordinate system for onemulti-array tool asσ_(a) ^((i))(z)=∫∫g ^((i))(ρ,z−z′)·σ(ρ,z′)·dρdz′,i=1,2, . . . ,N  (4)in which function g^((i))(ρ,z−z) is the combined two-dimensional (2D)Born (or Doll) geometrical factor, which describes the response of thei-th individual array at a given frequency, ρ(ρ,z) is the 2D trueformation conductivity distribution, and N is the number of triadreceivers in the MCI tool. The Born approach provides analysis of theresponse of the MCI tool, where contributions from the formation aretaken as a perturbation from background conductivity. Using a Bornapproach, a response for zero conductivity corresponds to thegeometrical factor.

To produce a new log, a weighted sum of the individual array readingscan be computed over a depth window from z_(min) to z_(max) surroundingthe output logging point, as

$\begin{matrix}{{{\sigma_{RDF}^{(j)}(z)} = {\sum\limits_{i = 1}^{N}{\sum\limits_{z^{\prime} = z_{\min}}^{z_{\max}}{{w_{i}^{(j)}\left( z^{\prime} \right)} \cdot {\sigma_{a}^{(i)}\left( {z - z^{\prime}} \right)}}}}},{j = 1},2,\ldots\mspace{14mu},M} & (5)\end{matrix}$where, σ_(RDF) ^((j))(z) is the apparent conductivity of theradial-direction focusing (RDF) log curve, σ_(a) ^((i)) is theskin-effect corrected (SEC) and borehole-corrected log of the i-thsubarray, and M is the total number of the RDF targeted radial depths.The depth window z_(min) to z_(max) provides a range over which thereceived signals contributes significantly with the measurement.Equation (4) can be used to provide the RDF processing.

Substituting equation (4) into equation (5) yields the followingequation:

$\begin{matrix}{{{\sigma_{RDF}^{(j)}(z)} = {\sum\limits_{i = 1}^{N}{\sum\limits_{z^{\prime} = z_{\min}}^{z_{\max}}{{w_{i}^{(j)}\left( z^{\prime} \right)} \cdot {\int{\int{{g^{(i)}\left( {\rho,{z - z^{\prime}}} \right)}\;\sigma\;{\left( {\rho,z^{\prime}} \right) \cdot d}\;\rho\;{dz}^{\prime}}}}}}}},} & (6) \\{or} & \; \\{{{\sigma_{RDF}^{(j)}(z)} = {\int{\int{{g_{RDF}^{(j)}\left( {\rho,{z - z^{\prime}}} \right)}\;\sigma\;{\left( {\rho,z^{\prime}} \right) \cdot d}\;\rho\;{dz}^{\prime}}}}},} & (7) \\{where} & \; \\{{{g_{RDF}^{(j)}\left( {\rho,z} \right)} = {\sum\limits_{i = 1}^{N}{\sum\limits_{z^{\prime} = z_{\min}}^{z_{\max}}{{w_{i}^{(j)}\left( z^{\prime} \right)} \cdot {g^{(i)}\left( {\rho,{z - z^{\prime}}} \right)}}}}},} & (8)\end{matrix}$The function g_(RDF) ^((j))(ρ,z) in equation (8) is a 2D responsefunction defining the ideal features of 2D focusing and it is oftenreferred to as the “target” function of the 2D RDF processing. Thefunction g^((j))(ρ,z) is the combined (loop-source or point-source) Born(or Doll) response function or geometrical factor of each individualsubarray. Hence, it is a weighted sum of the Born (or Doll) responsefunction of each individual subarray. As g^((j))(ρ,z) is dependent onbackground conductivity, and hence g_(RDF) ^((j))(ρ,z) is a function ofthe conductivity.

Equation (8) can be used to design a filter. In equation (8), the outputto be determined are the weights w_(i) ^((j))(z′), which provide filtercoefficients. The g_(RDF) ^((j))(ρ,z) is a desired shape function toprocess incoming raw measurements of the conductivity, such that thefilter is adjusted to provide the desired shape. The g_(RDF) ^((j))(ρ,z)shape function can be selected to provide a desired resolution and is aninput to equation (8). As noted above, g^((j))(ρ,z) is a geometricalfactor of an individual subarray and is a known input for equation (8).For example, a VGF curve, similar to those of FIG. 3, provides the inputgeometrical factor for a selected receiver array, which may be definedby its separation distance from a transmitter.

Also in equation (8), the normalization condition of g_(RDF) ^((j))(ρ,z)can be obtained as

$\begin{matrix}{{\int_{0}^{+ \infty}{\int_{- \infty}^{+ \infty}{{{g_{RDF}^{(j)}\left( {\rho,z^{\prime}} \right)} \cdot d}\;\rho\;{dz}^{\prime}}}} = 1} & (9) \\{or} & \; \\{{\sum\limits_{i = 1}^{N}{\sum\limits_{z^{\prime} = z_{\min}}^{z_{\max}}{w_{i}\left( z^{\prime} \right)}}} = 1.} & (10)\end{matrix}$Equations (9) and (10) provide normalization constraints on equation(8). The filter weights, w_(i)(z′), can be pre-determined using theoptimization to solve equation (8) with other constraints such asequations (9) or (10). For different background conductivities, filterweights can be generated and stored in a library/look-up table. Whenapplying a filter, the filter weights for a given conductivity can beobtained from the library/look-up table.

After the above RDF processing, the processed curves have variedvertical resolutions, which may range from 1 ft to 8 ft. In general,several sets of final log curves with different vertical resolutions(e.g., 1 ft, 2 ft, etc) can be produced by using the vertical-resolutionmatching (VRM) or vertical-resolution enhancement (VRE). For example,each receiver triad 214-1, 214-2, 214-3, and 214-4 as shown in FIG. 2 isat a different distance from transmitter triad 212 and will have adifferent depth of investigation. In addition, a log for each of thesereceivers will have an associated resolution. A vertical resolution, forinstance, provides a measurement distance that indicates the ability ofa logging tool to determine changes of data with respect to thehorizontal direction to the tool. Vertical-resolution matching cancombine logs of different depths of investigation that have the samevertical resolution. VRM/VRE processing involves processing to extracthigh vertical resolution information from high-resolution curves andimpose them onto the low-resolution curves. These curves can beimplemented by using the conventional induction-log VRM/VRE processing.

In a similar way, the high resolution information of the high resolutioncurves associated with the short distance receivers can be used toconstraint the inversion of the longer distance arrays. Constraining theinversion of the longer distance arrays with the high resolution curvesassociated with the short distance receivers achieves a resolution matchset of curves. This technique provides an alternative way of processingthe combined curves of equations (2) and (3) to achieve the multipledepth resolution match results.

An alternative method to derive resolution match variable depth ofinvestigation for the component combinations of equations (2) and (3)can be achieved by using constrained inversion of the combinedmeasurements from the different arrays of the MCI tool. That is, thecombined signals of equations (2) and (3) generated by the differentarrays of the MCI tool, which are located at different distances fromthe transmitter, can be use as input in an inversion algorithm, in whichthe information from the short arrays is used as constraints in theinversion of the deeper arrays.

In various embodiments, processing techniques for the combined signalsof VMD and HMD of a MCI tool can provide enhancements over ZZ processingresults of traditional induction tools. These processing techniques cancombine the VMD and the HMD of the MCI tool to utilize the improvedradial and vertical characteristics of the combined signal. In variousembodiments, the HMD signals combined with the VMD can includecontributions from both horizontal directions. By combining the VMD, theHMD, and the multiple spacings of the MCI tool, such processing candeliver higher resolution than standard induction processing that usesonly the VMD information from different arrays. Such combined signalprocessing, as described herein, has reduced borehole effect and reducedshoulder bed effect. The effect of eccentricity is also reduced due toless sensitivity of the combined signal to the borehole region, ascompared with the traditional array induction processing, that uses theVMD exclusively. The component combinations of these processingtechniques can generate additional information useful in the assessmentof quality of the MCI measurement and useful to facilitateinterpretation of log data.

FIG. 5 shows features of an embodiment of an example method ofprocessing MCI data. The processing can be realized under the control ofa processor. At 510, signals generated from operating a multi-componentinduction tool in a wellbore are acquired. The multi-component inductiontool can have a plurality of receiver arrays. Acquiring signalsgenerated from operating the multi-component induction tool can includeacquiring signals from a plurality of receiver triads disposed axiallyon the multi-component induction tool in response to a transmitter triaddisposed axially on the multi-component induction tool generating probesignals, the receiver triads are arranged at different distances fromthe transmitter triad. At 520, for each receiver array at a fixedfrequency, a combination of components from the acquired signals isgenerated, where the components correspond to components of an apparentconductivity tensor. The combination of components can include XX, YY,and ZZ components or the combination of components can includecross-coupling components. A format of the combination of components canbe selected based on a targeted specific feature of the formation. Forexample, the targeted specific feature can be anisotropy, bedboundaries, or fractures. At 530, combinations measured from theplurality of receiver arrays are mixed together. At 540, data, withrespect to evaluation of formation around the wellbore, is generatedfrom the mixing of the combinations together.

The method can include additional processing to take into considerationoperation parameters other than using receiver arrays at differentdistances from a transmitter or transmitter array. The method caninclude acquiring signals generated from operating the multi-componentinduction tool at multiple subarrays and a number of differentfrequencies; generating, for each receiver array at each frequency, acombination of components from the acquired signals, the componentscorresponding to components of an apparent conductivity tensor; mixingtogether combinations measured from the plurality of receiver arrays atthe different frequencies; and generating data with respect toevaluation of formation around the wellbore, from mixing thecombinations together. For multiple receiver arrays operated at onefrequency or operated over different frequencies, the method can includeperforming acquisition of signals and generation of the combinations fora number of different locations to which the multi-component inductiontool is disposed along the borehole; and mixing together thecombinations from the different locations.

Generating combinations of components can include, for each receiverarray, generating aZZ+bXX+cYY with a, b, and c being numericalcoefficients or generating dIJ+eJI, where IJ and JI are differentcomponents of the 9 possible conductivity combinations with d and ebeing numerical coefficients. Generating data with respect to evaluationof formation around the wellbore can include performingvertical-resolution matching/enhancement based on the mixed togethercombinations measured from the plurality of receiver arrays operated atmultiple frequencies.

Generating data with respect to evaluation of formation around thewellbore can include separating the combination of components for eachreceiver array into two sets based on distance of each receiver arrayfrom a transmitter array from which the acquiring signals are based. Oneset of the two sets can have combinations of components from receiverarrays categorized as short arrays, while the other set of the two setscan have combinations of components from receiver arrays categorized asdeeper arrays relative to the short arrays. The combination ofcomponents for each receiver array can be used in an inversion process,in which data from the combinations or inversion of components of theshort arrays is used as constraints in inverting the combinations ofcomponents of the deeper arrays. The categorization of short arrays anddeep arrays can be based on a selected threshold. For a selecteddistance threshold, receiver arrays having separation distances from thetransmitter less than the threshold are categorized as a short array andreceiver arrays having separation distances from the transmitter greaterthan the threshold are categorized as a deep array. For a separationdistance equal to the threshold, the associated receiver array can becategorized as either a short array or a deep array.

Filters can be applied to the combinations of components from thereceiver arrays. The filters can be realized as being weights generatedfrom generating an apparent conductivity of a radial-direction focusinglog. Generating data from the mixed together combinations includes usingfilter weights from a library/look-up table for different backgroundconductivities.

In various embodiments, a machine-readable storage device can compriseinstructions stored thereon, which, when performed by a machine, causethe machine to perform operations, the operations comprising one or morefeatures similar to or identical to features of methods and techniquesdescribed herein. The physical structure of such instructions may beoperated on by one or more processors. Executing these physicalstructure can cause the machine to perform operations to acquire signalsgenerated from operating a MCI tool in a wellbore, the MCI tool having aplurality of receiver arrays; to generate, for each receiver array at afixed frequency, a combination of components from the acquired signals,the components corresponding to components of an apparent conductivitytensor; to mix together combinations measured from the plurality ofreceiver arrays tool; and to generate data, with respect to evaluationof formation around the wellbore, from the mixed together combinations.The combination of components can include, but are not limited to, XX,YY, and ZZ components or the combination of components can includecross-coupling components such as XZ and ZX. The instructions caninclude instructions to operate a MCI tool having one or moretransmitters and one or more receivers to provide data to a processingunit in accordance with the teachings herein. Further, amachine-readable storage device, herein, is a physical device thatstores data represented by physical structure within the device.Examples of machine-readable storage devices can include, but are notlimited to, read only memory (ROM), random access memory (RAM), amagnetic disk storage device, an optical storage device, a flash memory,and other electronic, magnetic, and/or optical memory devices.

In various embodiments, a system can comprise a tool structure and aprocessing unit to process data from operating the tool structure. Thetool structure can be a MCI tool structure having a transmitter arrayand a plurality of receiver arrays, where the MCI tool structure iscapable of operating in a wellbore. Each receiver array may be realizedby a receiver triad disposed axially on the tool structure and thetransmitter array may be realized by a transmitter triad disposedaxially on the tool structure, where the each receiver arrays aredisposed at different distances from the transmitter triad. Theprocessing unit can be structured: to acquire signals from the toolstructure; to generate, for each receiver array at a fixed frequency, acombination of components from the acquired signals, the componentscorresponding to components of an apparent conductivity tensor; to mixtogether combinations measured from the plurality of receiver arraystool; and to generate data, with respect to evaluation of formationaround the wellbore, from mixing combinations together. The combinationof components can include, but are not limited to XX YY, and ZZcomponents or the combination of components including cross-couplingcomponents.

The processing unit can be structured to perform processing techniquessimilar to or identical to the techniques discussed herein. Theprocessing unit may control selective activation of the transmitters andacquisition of signals from the receivers. Alternatively, a control unitcan be used to control and manage the transmitters and receivers. Theprocessing unit can be configured to process the acquired signals andprocess data related to or generated from the acquired signals. Theprocessing unit may be arranged as an integrated unit or a distributedunit. The processing unit can be disposed at the surface of a wellboreto process MCI data from operating the tool structure downhole. Theprocessing unit be disposed in a housing unit integrated with the toolstructure or arranged downhole in the vicinity of the tool structure.The processing unit may process in real time multi-component inductiondata in a manner similar to or identical to the techniques discussedherein.

FIG. 6 depicts a block diagram of features of an example system 600operable to control a multi-component induction tool to conductmeasurements in a wellbore and to process data derived from operatingthe multi-component induction tool. The system 600 includes a toolstructure 605 having an arrangement of transmitter antenna(s) 612 andreceiver antenna(s) 614 operable in a wellbore. The arrangements of thetransmitter antenna(s) 612 and the receiver antenna(s) 614 of the tool605 can be realized similar to or identical to arrangements discussedherein. The system 600 can also include a controller 625, a memory 635,an electronic apparatus 665, and a communications unit 640. Thecontroller 625 and the memory 635 can be arranged to operate the tool605 to acquire measurement data as the tool 605 is operated. Thecontroller 625 and the memory 635 can be realized to control activationof selected ones of the transmitter antennas 612 and data acquisition byselected one of the receiver antennas 614 in the tool 605 and to manageprocessing schemes with respect to data derivable from measurementsusing tool 605 as described herein. Processing unit 620 can bestructured to perform the operations to manage processing schemes in amanner similar to or identical to embodiments described herein.

Electronic apparatus 665 can be used in conjunction with the controller625 to perform tasks associated with taking measurements downhole withthe transmitter antenna(s) 614 and the receiver antenna(s) 612 of thetool 605. The communications unit 640 can include downholecommunications in a drilling operation. Such downhole communications caninclude a telemetry system.

The system 600 can also include a bus 627, where the bus 627 provideselectrical conductivity among the components of the system 600. The bus627 can include an address bus, a data bus, and a control bus, eachindependently configured. The bus 627 can also use common conductivelines for providing one or more of address, data, or control, the use ofwhich can be regulated by the controller 625. The bus 627 can beconfigured such that the components of the system 600 are distributed.Such distribution can be arranged between downhole components such asthe transmitter antenna(s) 612 and the receiver antenna(s) 614 of thetool 605 and components that can be disposed on the surface of a well.Alternatively, various of these components can be co-located such as onone or more collars of a drill string or on a wireline structure.

In various embodiments, peripheral devices 645 can include displays,additional storage memory, and/or other control devices that may operatein conjunction with the controller 625 and/or the memory 635. In anembodiment, the controller 625 can be realized as one or moreprocessors. The peripheral devices 645 can be arranged to operate inconjunction with display unit(s) 655 with instructions stored in thememory 635 to implement a user interface to manage the operation of thetool 605 and/or components distributed within the system 600. Such auser interface can be operated in conjunction with the communicationsunit 640 and the bus 627. Various components of the system 600 can beintegrated with the tool structure 605 such that processing identical toor similar to the processing schemes discussed with respect to variousembodiments herein can be performed downhole in the vicinity of themeasurement or at the surface.

FIG. 7 depicts an embodiment of a system 700 at a drilling site, wherethe system 700 includes an apparatus operable to control amulti-component induction tool to conduct measurements in a wellbore andto process data derived from operating the multi-component inductiontool. The system 700 can include a tool 705-1, 705-2, or both 705-1 and705-2 having an arrangement of transmitter antennas and receiverantennas operable to make measurements that can be used for a number ofdrilling tasks including, but not limited to, processing multi-componentinduction data. The tools 705-1 and 705-2 can be structured identical toor similar to a tool architecture or combinations of tool architecturesdiscussed herein, including control units and processing units operableto perform processing schemes in a manner identical to or similar toprocessing techniques discussed herein. The tools 705-1, 705-2, or both705-1 and 705-2 can be distributed among the components of system 700.The tools 705-1 and 705-2 can be realized in a similar or identicalmanner to arrangements of control units, transmitters, receivers, andprocessing units discussed herein. The tools 705-1 and 705-2 can bestructured, fabricated, and calibrated in accordance with variousembodiments as taught herein.

The system 700 can include a drilling rig 702 located at a surface 704of a well 706 and a string of drill pipes, that is, drill string 729,connected together so as to form a drilling string that is loweredthrough a rotary table 707 into a wellbore or borehole 711-1. Thedrilling rig 702 can provide support for the drill string 729. The drillstring 729 can operate to penetrate rotary table 707 for drilling theborehole 711-1 through subsurface formations 714. The drill string 729can include a drill pipe 718 and a bottom hole assembly 721 located atthe lower portion of the drill pipe 718.

The bottom hole assembly 721 can include a drill collar 716 and a drillbit 726. The drill bit 726 can operate to create the borehole 711-1 bypenetrating the surface 704 and the subsurface formations 714. Thebottom hole assembly 721 can include the tool 705-1 attached to thedrill collar 716 to conduct measurements to determine formationparameters. The tool 705-1 can be structured for an implementation as aMWD system such as a LWD system. The housing containing the tool 705-1can include electronics to initiate measurements from selectedtransmitter antennas and to collect measurement signals from selectedreceiver antennas. Such electronics can include a processing unit toprovide analysis of multi-component induction data over a standardcommunication mechanism for operating in a well. Alternatively,electronics can include a communications interface to providemeasurement signals collected by the tool 705-1 to the surface over astandard communication mechanism for operating in a well, where thesemeasurements signals can be analyzed at a processing unit 720 at thesurface to provide analysis of multi-component induction data.

During drilling operations, the drill string 729 can be rotated by therotary table 707. In addition to, or alternatively, the bottom holeassembly 721 can also be rotated by a motor (e.g., a mud motor) that islocated downhole. The drill collars 716 can be used to add weight to thedrill bit 726. The drill collars 716 also can stiffen the bottom holeassembly 721 to allow the bottom hole assembly 721 to transfer the addedweight to the drill bit 726, and in turn, assist the drill bit 726 inpenetrating the surface 704 and the subsurface formations 714.

During drilling operations, a mud pump 732 can pump drilling fluid(sometimes known by those of skill in the art as “drilling mud”) from amud pit 734 through a hose 736 into the drill pipe 718 and down to thedrill bit 726. The drilling fluid can flow out from the drill bit 726and be returned to the surface 704 through an annular area 740 betweenthe drill pipe 718 and the sides of the borehole 711-1. The drillingfluid may then be returned to the mud pit 734, where such fluid isfiltered. In some embodiments, the drilling fluid can be used to coolthe drill bit 726, as well as to provide lubrication for the drill bit726 during drilling operations. Additionally, the drilling fluid may beused to remove subsurface formation cuttings created by operating thedrill bit 726.

In various embodiments, the tool 705-2 may be included in a tool body770 coupled to a logging cable 774 such as, for example, for wirelineapplications. The tool body 770 containing the tool 705-2 can includeelectronics to initiate measurements from selected transmitter antennasand to collect measurement signals from selected receiver antennas. Suchelectronics can include a processing unit to provide analysis ofmulti-component induction data over a standard communication mechanismfor operating in a well. Alternatively, electronics can include acommunications interface to provide measurement signals collected by thetool 705-2 to the surface over a standard communication mechanism foroperating in a well, where these measurements signals can be analyzed ata processing unit 720 at the surface to provide analysis ofmulti-component induction data. The logging cable 774 may be realized asa wireline (multiple power and communication lines), a mono-cable (asingle conductor), and/or a slick-line (no conductors for power orcommunications), or other appropriate structure for use in the borehole711-2. Though FIG. 7 depicts both an arrangement for wirelineapplications and an arrangement for LWD applications, the system 700 maybe also realized for one of the two applications.

Although specific embodiments have been illustrated and describedherein, it will be appreciated by those of ordinary skill in the artthat any arrangement that is calculated to achieve the same purpose maybe substituted for the specific embodiments shown. Various embodimentsuse permutations and/or combinations of embodiments described herein. Itis to be understood that the above description is intended to beillustrative, and not restrictive, and that the phraseology orterminology employed herein is for the purpose of description.Combinations of the above embodiments and other embodiments will beapparent to those of skill in the art upon studying the abovedescription.

What is claimed is:
 1. A method comprising: acquiring signals generatedfrom operating a multi-component induction tool in a wellbore, themulti-component induction tool having a plurality of receiver arrays,each receiver array comprising a receiver triad; generating, for eachreceiver array at a fixed frequency, a combination of components fromthe acquired signals, the components corresponding to components of anapparent conductivity tensor, wherein generating the combination ofcomponents comprises generating vertical magnetic dipole (VIVID) dataand horizontal magnetic dipole (HMD) data; for each of one or morereceiver arrays, combining a geometric factor associated with eachreceiver of the receiver triad of the receiver array to form arespective combination of the geometric factors, wherein the receiversof the receiver triad are oriented in different directions; generatingfilters based on (i) the one or more combinations of geometric factorsand (ii) a target function, wherein each of the one or more combinationsof geometric factors correlates the electromagnetic properties of thedownhole formation to the apparent conductivity tensor; mixing togetherthe combination of VIVID data and HMD data measured from the pluralityof receiver arrays wherein the mixing comprises applying the filters tothe one or more combinations of components; and generating data, withrespect to evaluation of a formation around the wellbore, from themixing together of combinations, wherein the data has an improvedresolution at multiple depths of investigation compared to the acquiredsignals.
 2. The method of claim 1, wherein generating the VIVID datacomprises generating ZZ coupling data, and wherein generating the HMDdata comprises generating XX coupling data and YY coupling data.
 3. Themethod of claim 1, further comprising: performing the acquiring ofsignals and the generating of the combinations for a number of differentlocations to which the multi-component induction tool is disposed alongthe wellbore; and mixing together the combinations from the differentlocations.
 4. The method of claim 1, wherein generating the VIVID dataand the HMD data comprises, for each receiver array and each frequency,at least one of generating aZZ+bXX+cYY with a, b, and c being numericalcoefficients and generating dIJ+e JI, IJ and JI being differentcomponents of the apparent conductivity tensor with d and e beingnumerical coefficients.
 5. The method of claim 1, wherein generatingdata with respect to evaluation of formation around the wellborecomprises performing vertical-resolution matching based on the mixedtogether combinations measured from the plurality of receiver arrays. 6.The method of claim 1, wherein generating data with respect toevaluation of formation around the wellbore comprises: separating thecombination of components for each receiver array into two sets based ona distance of each receiver array from a transmitter array from whichthe acquired signals is based, one set of the two sets havingcombinations of components from the plurality of receiver arrayscategorized as short arrays and the other set of the two sets havingcombinations of components from the plurality of receiver arrayscategorized as deeper arrays relative to the short arrays; and using thecombination of components for each receiver array in an inversionprocess, in which data from the combinations of components of the shortarrays is used as constraints in inverting the combinations ofcomponents of the deeper arrays.
 7. The method of claim 1, furthercomprising applying filters to the combinations of components from thereceiver arrays, the filters being weights generated from generating anapparent conductivity.
 8. The method of claim 7, wherein generating datafrom the mixed together combinations comprises using filter weights fordifferent background conductivities.
 9. The method of claim 1, furthercomprising selecting a format of the combination of components based ona specific feature of the formation.
 10. The method of claim 9, whereinthe specific feature is at least one of anisotropy, bed boundaries, andfractures.
 11. The method of claim 1, wherein acquiring signalsgenerated from operating the multi-component induction tool comprisesacquiring signals from a plurality of receiver triads disposed axiallyon the multi-component induction tool in response to a transmitter triaddisposed axially on the multi-component induction tool generating probesignals, the receiver triads at different distances from the transmittertriad.
 12. One or more non-transitory machine-readable media comprisingprogram code for evaluation of a formation, the program code to: acquiresignals generated from operating a multi-component induction tool in awellbore, the multi-component induction tool having a plurality ofreceiver arrays, each receiver array comprising a receiver triad;generate, for each receiver array at a fixed frequency, a combination ofcomponents from the acquired signals, the components corresponding tocomponents of an apparent conductivity tensor, wherein generating thecombination of components comprises generating vertical magnetic dipole(VIVID) data and horizontal magnetic dipole (HMD) data; for each of oneor more receiver arrays, combine, under control of a processor, ageometric factor associated with each receiver of the receiver triad ofthe receiver array to form a respective combination of the geometricfactors, wherein the receivers of the receiver triad are oriented indifferent directions; generate, under control of the processor, filtersbased on (i) the one or more combinations of geometric factors and (ii)a target function, wherein each of the one or more combinations ofgeometric factors correlates the electromagnetic properties of thedownhole formation to the apparent conductivity tensor; mix together thecombination of VIVID data and HMD data measured from the plurality ofreceiver arrays, wherein the mixing comprises applying the filters tothe one or more combinations of components; and generate data, withrespect to evaluation of the formation around the wellbore, from themixed together combinations, wherein the data has an improved resolutionat multiple depths of investigation compared to the acquired signals.13. The one or more non-transitory machine-readable media of claim 12,wherein the program code to generate the VIVID data comprises programcode to generate ZZ coupling data, and wherein the program code togenerate the HMD data comprises program code to generate XX couplingdata and YY coupling data.
 14. The one or more non-transitorymachine-readable media of claim 12, wherein the program code is to:perform acquisition of signals and generation of the combinations for anumber of different locations to which the multi-component inductiontool is disposed along the wellbore; and mix together the combinationsfrom the different locations.
 15. The one or more non-transitorymachine-readable media of claim 12, wherein the program code to generatethe VIVID data and the HMD data comprises, for each receiver array atthe fixed frequency, at least one of program code to generateaZZ+bXX+cYY with a, b, and c being numerical coefficients and programcode to generate dIJ+e JI, IJ and JI being different components of theapparent conductivity tensor with d and e being numerical coefficients.16. The one or more non-transitory machine-readable media of claim 12,wherein the program code to generate data with respect to evaluation offormation around the wellbore comprises program code to performvertical-resolution matching based on the mixed together combinationsmeasured from the plurality of receiver arrays.
 17. The one or morenon-transitory machine-readable media of claim 12, wherein the programcode to acquire signals generated from operating the multi-componentinduction tool comprises program code to acquire signals from aplurality of receiver triads disposed axially on the multi-componentinduction tool in response to a transmitter triad disposed axially onthe multi-component induction tool generating probe signals, thereceiver triads at different distances from the transmitter triad. 18.An apparatus comprising: a multi-component induction tool having atransmitter array and a plurality of receiver arrays, wherein themulti-component induction tool is configured for operation in a wellboreand each receiver array comprises a receiver triad; a processor; and amachine-readable medium having program code executable by the processorto cause the apparatus to: acquire signals generated from thetransmitter array; generate, for each receiver array of the plurality ofreceiver arrays at a fixed frequency, a combination of components fromthe acquired signals, the components corresponding to components of anapparent conductivity tensor, wherein generating the combination ofcomponents comprises generating vertical magnetic dipole (VMD) data andhorizontal magnetic dipole (HMD) data; for each of one or more receiverarrays, combine, under control of the processor, a geometric factorassociated with each receiver of the receiver triad of the receiverarray to form a respective combination of the geometric factors, whereinthe receivers of the receiver triad are oriented in differentdirections; generate, under control of the processor, filters based on(i) the one or more combinations of geometric factors and (ii) a targetfunction, wherein each of the one or more combinations of geometricfactors correlates the electromagnetic properties of the downholeformation to the apparent conductivity tensor; mix together thecombination of VMD data and HMD data measured from the plurality ofreceiver arrays wherein the mixing comprises applying the filters to theone or more combinations of components; and generate data, with respectto evaluation of a formation around the wellbore, from the mixedtogether combinations.
 19. The apparatus of claim 18, wherein theprogram code executable by the processor to cause the apparatus togenerate the VIVID data comprises program code executable by theprocessor to cause the apparatus to generate ZZ coupling data, andwherein the program code executable by the processor to cause theapparatus to generate the HMD data comprises program code executable bythe processor to cause the apparatus to generate XX coupling data and YYcoupling data.
 20. The apparatus of claim 18, wherein the program codeexecutable by the processor to cause the apparatus to generate the VIVIDdata and the HMD data comprises, for each receiver array at the fixedfrequency, at least one of program code executable by the processor tocause the apparatus to generate aZZ+bXX+cYY with a, b, and c beingnumerical coefficients and program code executable by the processor tocause the apparatus to generate dIJ+e JI, IJ and JI being differentcomponents of the apparent conductivity tensor with d and e beingnumerical coefficients.